This section provides background information related to the present disclosure which is not necessarily prior art.
As explained in WO 2008/098380 assigned to a common owner of the within application, ingress of fluids such as gases or liquids into wellbores, where such fluids may (and typically do) then migrate to surface in the area between the wellbore and the casing and thus undesirably escape into the atmosphere, are a serious and increasing environmental concern. Specifically, fluids which seep into wellbores commonly comprise gases and liquids which are toxic, such as for example and including hydrogen sulfide, and/or are greenhouse gases such as methane. This is occurring more frequently in view of the increasing number of hydrocarbon wells being drilled. The path of such fluids to the surface can arise due to fractures around the wellbore, fractures in the production tubing, poor casing to cement/cement-to-formation bond, channeling in the cement, or various other reasons.
The ingress of fluid into a wellbore and subsequent fluid migration to surface is known as casing vent flow (“CVF”) or gas migration (“GM”) and may occur at any time in the life of the well, and even when the well has been sealed when no longer sufficiently productive.
Wellbores found to have aberrant or undesired fluid ingress (generally, gas or liquid hydrocarbon) and migration (i.e., a ‘leak’) must be repaired to stop such ingress. This may entail halting a producing well, or making the repairs on an abandoned or suspended well. The repair of these situations does not generate revenue for the gas/oil company, and can cost millions of dollars per well to fix the problem.
In order to deal with the leak and thus prevent the ingress of fluids into a wellbore, a basic strategy in the prior art included: identifying the location in the wellbore where there is ingress of liquids such as gas; communicate with the leaking fluid source (i.e. make holes in production casing and/or cement in order to effectively access the formation), and; plug, cover or otherwise stop the leak (i.e. inject or apply cement above and into the culprit formation in order to seal or ‘plug’ the gas source, preventing future leaks).
Materials and methods for stopping leaks associated with oil or gas wells are known, and usually involve injection of a liquid or semi-liquid matrix that sets into a gas-impermeable layer. For example, U.S. patent 55/003,227 to Saponja et al describes methods of terminating undesirable gas or liquid hydrocarbon migration in wells. U.S. Pat. No. 5,327,969 to Sabins et al describes methods of preventing gas or liquid hydrocarbon migration during the primary well cementing stage.
Before the leak can be stopped, however, it must first be identified and its location in the wellbore determined.
It is known, and existing systems for leak detection rely on the fact, that ingress of fluids into a wellbore typically generates a noise (acoustic signal), such as a “hiss” from high pressurized gas seeping into the wellbore, or from fluid intermittently “bubbling” into a wellbore.
For such reason the prior art methods and apparatus, in an attempt to identify a location in a wellbore of fluid ingress, utilized an acoustic sensing device such as a microphone or piezoelectric sensor, for attempting to identify a location of a leak in a wellbore. In this regard, the prior art apparatus and methods typically comprise an acoustic sensing device such as a microphone, typically lowered into a wellbore at the end of a cable or wire, and suspended at a depth of interest. Acoustic activity at that depth is recorded for a short period of time. The device is then raised up a further short distance (repositioned) and the process repeated. The recording interval may range from about 10 seconds to about 1 minute, and the repositioning distance from about 2 meters to about 5 meters. Longer recording intervals and shorter repositioning distances may give more accurate data, but at the expense of time.
In the prior art, once acoustic data as described above has been acquired for the complete length of the wellbore, the amplitudes of the acoustic signals obtained (which would include noise of a leak “noise”) are typically processed to determine their respective strength or power, the theory being that the strongest or most powerful acoustic signal will likely obtained at the location in the well which is experiencing acoustic noise due to the ingress of fluid at that location into the wellbore. These prior art techniques only work well for high rate leaks (i.e., where the ingress of fluid into the wellbore is high and generating significant and high power acoustic signal from a pinpoint location in the well bore), and where there is relatively low background noise or little interference from other noise sources such as surface noise, and reverberation and resulting sound amplification at other locations in the well is not occurring or is not significant. Using comparisons of the power or strength of the various acoustic signals in such manner as done in the prior art is highly unsatisfactory, as reverberations in wellbores frequently produces higher noise levels at locations within the wellbore considerable remote from the location in the wellbore which is the actual source of the acoustic event, and are thus unsatisfactory for attempting to precisely locate the location of fluid ingress in a wellbore.
As well, where fluid ingress into the wellbore is not under high pressure (but may be still significant in terms of amount) and thus the corresponding acoustic signal is substantially reduced in magnitude and/or is of a sporadic nature such as when gases or liquids bubble periodically into the wellbore, the ability to identify which acoustic signal (and thus the location in the wellbore) that is experiencing fluid ingress is considerably more difficult under the aforementioned prior art methods, and is very unreliable. Again, factors such as reverberation and echoes (as nearly always occur with acoustic signals in wellbores) and/or interfering surface noise each have the undesirable consequence of often making acoustic signals remote from the location of the acoustic event stronger and possessing more power than the acoustic signal emanating from a location in the wellbore most proximate the acoustic event.
Accordingly, the prior art methods of acoustic signal analysis, using signal strength and power (RMS, weighted mean, etc) as a method for comparing acoustic signals as a method for determining which acoustic signal and associated location in a wellbore is likely closest the source of fluid ingress in a well have failed, for the above reasons, to be consistently reliable in precisely locating the location of fluid ingress, even when many acoustic signals are logged over relatively narrow spaced intervals in a wellbore.
Indeed, there has been at least one instance to the inventor's knowledge where in excess of $1 million (Can.) was incurred in initial attempts to locate a leak in a wellbore, wherein prior art acoustic signal analysis methods incorrectly suggested certain locations in a wellbore were the source of the leak. As a result, various (incorrect) locations in such wellbore were, through laborious effort and expense, injected with cement in an attempt to “seal” the wellbore at such locations from CVM and fluid ingress, but which efforts were not successful due to prior art methods being unable to satisfactorily analyze the acoustic signals to as to be able to accurately identify the location the wellbore fluid ingress was occurring.
In view of the above, a real need exists for an improved method to better detect and locate fluid ingress and egress in a wellbore.